1. Field of the Invention
The present invention relates generally to managing fluid characteristics of a fluid, and specifically to systems, apparatus, program product, and methods to estimate and manage flowing fluid characteristics of a fluid stream flowing through a pipeline.
2. Description of Related Art
Crude oil generally comprises a complex mixture of hydrocarbons of the various molecular weights plus other organic compounds of variable specific gravity and viscosity. Crude oil, however, also includes various impurities including gas, water, salt, etc. along with other chemicals compounds used in the extraction process. Accordingly, crude oil received from production wells is typically routed through a processing facility such as, for example, a gas oil separation plant (GOSP). Such gas oil separation plant can include, for example, a 2 or 3-stage oil-gas separation facility, with a 2 or 3-stage dehydrator/desalting train. A typical gas oil separation plant processes ˜300 MBD of crude and ˜100 MBD of water. The gas oil separation plants are generally designed to handle watercuts up to 30%, and some have been modified and retrofitted to handle higher watercuts. The crude oil exiting the gas oil separation plant is considered dehydrated dead crude oil.
Crude oil extracted from each separate oil well for processing at the gas oil separation plant, has generally been found to have its own unique characteristics. Responsively, in order to classify the oil coming from each separate oil well, the oil industry has developed various methodologies of grading the different types of crude oil. One of the most popular methodologies is the use of a grading system based on specific gravity/density developed by the American Petroleum Institute (API), a U.S trade association representing various companies involved in production, refinement, and distribution of oil and gas. According to such methodology, each volume of crude oil is assigned an API degree rating or grade which relates its specific gravity with that of water. According to the API scale, water is assigned a 10 degree API rating.
Crude oil is classified as light, medium, or heavy, according to its measured API gravity, with the lighter crude oil assigned a higher API gravity. In general, crude oil having a rating above approximately 31 API is considered in the industry to be “light,” with oil having a rating (grade) above approximately 40 API considered to be “very light.” Crude oil having an API gravity between approximately 22 and 31 API is considered in the industry to be “medium.” Crude oil having an API gravity below approximately 22 is considered in the industry to be “heavy.” Various other rating schemes are used to further define each specific volume of crude oil. For example, oil having a low sulphur content is identified as being “sweet,” while crude oil having a high sulphur content is identified as being “sour.”
The commercial value of a volume of crude oil generally depends upon its API gravity degree and on the needs of the buyer. Nevertheless, in general, crude oil having an API gravity of between 40 and 45 API tends to have the greatest commercial value. Accordingly, crude oil producers running multiple wells may wish to control production of the individual wells so that the overall deliverable volume of crude oil is maintained within a selected range of values or at least maintained above a minimum value.
Conventional practice to determine the API gravity, so far, has been to collect fluid samples and to send the samples to a laboratory for manual fluid density estimation. Because, in most of the cases, the crude grade for a certain field does not change much (i.e., production from the same reservoir/reservoirs may have almost similar crude grades), this manual method is generally considered quite practical. The Applicant has recognized, however, that for cases with a complex crude blend (i.e., mix of several produced crude grades) from several wells, for example, the manual method is not practical. In this case, a real time estimation of crude grade is required in order to ensure that the required produced crude grade is met at all times, and to facilitate adjusting the flow rates of certain wells with specific crude grades in order to maintain or to bring the overall produced crude grade back to the required or desired limit if outside such limit.
Other newly developed methodologies of determining API gravity, exist. For example, U.S. Pat. No. 6,633,043 by Hegazi et al., titled “Method for Characterization of Petroleum Oils Using Normalized Time-Resolved Fluorescence Spectra,” describes a method based on time-resolved, laser-induced fluorescence spectroscopy for the characterization and fingerprinting of petroleum oils and other complex mixtures. The method depends on exciting the wavelength-resolved fluorescence spectra of manually obtained samples using ultraviolet pulsed laser radiation, measuring them at specific time gates within the temporal response of the excitation laser pulse, and comparing them in terms of their shapes, alone, without taking into account their relative intensities. U.S. Pat. No. 4,248,599 by Mommessin et al., titled “Process for Determining the API gravity of Oil by FID” describes determining the API gravity of a manually obtained oil sample by vaporizing its volatile and pyrolyzable components, measuring the ratio of the amount vaporized within a range of relatively high temperatures to the total amount vaporized. Again, the inventor has recognized that for cases with a complex crude blend (i.e., mix of several produced crude grades), such manual methodologies are not practical.
Although not understood by the inventor as being recognized in industry as an acceptable method for obtaining an API gravity of a complex blend of crude oil, the inventor recognizes that various methodologies of determining density of a fluid, nevertheless, exists. For example, U.S. Pat. No. 6,807,857, by Storm Jr. et al., titled “Method and Apparatus for Determining Density of a Flowing Fluid” describes a tool and process for measuring the density of a flowing fluid using two sets of measurement readings each taken from a corresponding pair of pressure assessment zones of a half-loop configured fluid conducting tool. WO 95/04869 by Kyllingstad, titled “A Method and an Apparatus for Measuring Density and Pressure Drop in a Flowing Fluid” similarly describes a pipe loop for receiving fluid from a main flow and having two branches each including a pair of spaced apart pressure sensors which provide data to calculate the liquids density and pressure loss per length unit. CN 13385, by Wang, titled “In-Line Continuous Measuring Method for Concentration and Density of Liquid Medium” describes a method and apparatus for measuring density which includes a vertical measuring tube for receiving an upward vertical flow and having two pressure measuring points, a differential pressure transducer used to measure their differential pressure, a medium temperature transducer positioned in the two pressure measuring points, and an ambient temperature transducer. U.S. Pat. No. 7,032,449 by Rivas, titled “Measurement of Fluid Properties in Vessel and Sensor for Same” describes a sensor for measuring properties of a fluid in a vessel having sensors spaced vertically along the sensor body inserted into a container. U.S. Pat. No. 6,687,643 by Cason Jr., titled “In-situ Sensor System and Method for Data Acquisition in Liquids” describes a system and method which measures the density of a static liquid in a container using pressure sensors positioned at two separate locations and separated by a fixed distance, and a temperature sensor. U.S. Pat. No. 3,033,040 by Piros, titled “Density Measuring Apparatus” describes a density meter for measuring the density of liquids, and controlling the proportion of constituent liquids present in blends so that the blend has a given density. The density meter determines density of fluid mixture extracted by a pump from a main flow using a pressure difference between a pressure maintaining (constant pressure) device positioned at an upper end of a vertical conduit and a pressure measuring device located at its lower end. U.S. Pat. No. 3,483,732 by Gogarty, titled “Continuous Density-Determining Device and Process” describes an apparatus which includes a conduit for extracting fluid to determine its density, a means for rendering a flowing liquid turbulent, a liquid flow measuring device, and a differential pressure transducer to determine a difference in pressure between two pressure points along the conduit.
Each of these devices, however, fails to provide a process for measuring the density of flowing fluid in a main flow line in real-time, and/or requires either an extraction pump, a separate sampling line to extract fluid from the main flow, a means to pump fluid upwardly through a vertical component, a collection or discharge line disruptively inserted into the main flow stream, or a combination thereof. Nor does either of these devices provide necessary means for estimating, and thus controlling, API gravity. Recognized by the inventor, therefore, is the need for a process setup that enables real-time estimation of fluid density and crude API gravity of a liquid fluid stream flowing through a pipeline in a processing facility, which does not require the addition of an external sampling line, the addition of a sampling or extraction pump, or application of a fluid collector, which would tend to impede or disrupt a fluid flow.